1. Field of the Disclosure
Embodiments disclosed herein generally relate to methods and apparatuses to threadedly connect one tubular member to another tubular member. More specifically, embodiments disclosed herein relate to a threaded connector having multiple contact surfaces to engage with each other.
2. Background Art
In oilfield exploration and production operations, various oilfield tubular members are used to perform important tasks, including, but not limited to, drilling the wellbore and casing a drilled wellbore. For example, a long assembly of drill pipes, known in the industry as a drill string, may be used to rotate a drill bit at a distal end to create the wellbore. Furthermore, after a wellbore has been created, a casing string may be disposed downhole into the wellbore and cemented in place to stabilize, reinforce, or isolate (among other functions) portions of the wellbore. As such, strings of drill pipe and casing may be connected together, such as end-to-end by threaded connections, in which a male “pin” member of a first tubular member is configured to threadably engage a corresponding female “box” member of a second tubular member. Alternatively, a casing string may be made-up of a series of male-male ended casing joints coupled together by female-female couplers. The process by which the threaded connections are assembled is called “making-up” a threaded connection, and the process by which the connections are disassembled is referred to “breaking-out” the threaded connection. As would be understood by one having ordinary skill, individual pieces (or “joints”) of oilfield tubular members may come in a variety of weights, diameters, configurations, and lengths.
Referring to FIG. 1, a perspective view is shown of one embodiment of a drilling rig 101 used to run one or more tubular members 111 (e.g., casing, drill pipe, etc.) downhole into a wellbore. As shown, the drilling rig 101 includes a frame structure known as a “derrick” 102, from which a traveling block 103 (which may include a top drive) suspends a lifting apparatus 105 (e.g., an elevator or a tubular (e.g., casing) running tool connected to the quill of a top drive) and a gripping apparatus 107 (e.g., slip assembly or “spider”) at the rig floor 109 may be used to manipulate (e.g., raise, lower, rotate, hold, etc.) a tubular member 111. The traveling block 103 is a device that is suspended from at or near the top of the derrick 102, in which the traveling block 103 may move up-and-down (i.e., vertically as depicted) to raise and/or lower the tubular member 111. The traveling block 103 may be a simple “pulley-style” block and may have a hook from which objects below (e.g., lifting apparatus 105 and/or top drive) may be suspended. Drilling rig 101 can be a land or offshore rig (e.g., drill ship) without departing from the scope of the present disclosure.
Additionally, the lifting apparatus 105 may be coupled below the traveling block 103 (and/or a top drive if present) to selectively grab or release a tubular member 111 as the tubular member 111 is to be raised and/or lowered within and from the derrick 102. As such, the top drive may include one or more guiding rails and/or a track disposed adjacent to the top drive, in which the guiding rails or track may be used to support and guide the top drive as the top drive is raised and/or lowered within the derrick. An example of a top drive is disclosed within U.S. Pat. No. 4,449,596, filed on Aug. 3, 1982, and entitled “Drilling of Wells with Top Drive Unit,” which is incorporated herein by reference.
Typically, a lifting apparatus 105 includes movable gripping members (e.g., slip assemblies) attached thereto and movable between a retracted (e.g., disengaged) position and an engaged position. In the engaged position, the lifting apparatus 105 supports the tubular member 111 such that the tubular member 111 may be lifted and/or lowered, and rotated if so equipped, e.g., by using a lifting apparatus that is a tubular (e.g., casing) running tool connected to the quill of the top drive. In the retracted position, the lifting apparatus 105 may release the tubular member 111 and move away therefrom to allow the tubular member 111 to be engaged with or removed from the lifting apparatus 105 and/or the gripping apparatus 107. For example, the lifting apparatus 105 may release the tubular member 111 after the tubular member 111 is threadably connected to a tubular string 115 supported by the gripping apparatus 107 (e.g., slip assembly or “spider”) at the rig floor 109 at the floor of the drilling rig 101.
Further, in an embodiment in which the drilling rig 101 includes a top drive and a tubular running tool, the tubular member 111 may be supported and gripped by the tubular running tool connected to the quill of the top drive. For example, the tubular running tool may include one or more gripping members that may move radially inward and/or radially outward. In such embodiments, these gripping members of a tubular running tool may move radially outward to grip an internal surface of the tubular member 111, such as with an internal gripping device and/or the gripping members of the tubular running tool may move radially inward to grip an external surface of the tubular member 111, such as with an external gripping device, however so equipped.
Further, the gripping apparatus 107 of the drilling rig 101 may be used to support and suspend the tubular string 115, e.g., by gripping, from the drilling rig 101, e.g., supported by the rig floor 109 or by a rotary table thereof. The gripping apparatus 107 may be disposed within the rig floor 109, such as flush with the rig floor 109, or may extend above the rig floor 109, as shown. As such, the gripping apparatus 107 may be used to suspend the tubular string 115, e.g., while one or more tubular members 111 are connected or disconnected from the tubular string 115.
Accordingly, tubular members that consist of casing may be placed in a wellbore to stabilize a formation and protect a formation against high wellbore pressures (e.g., wellbore pressures that exceed a formation pressure) that could damage the formation. Casing joints are generally larger tubular members of steel that may be coupled in an end-to-end manner by threaded connections, welded connections, and other connections known in the art. The connections are usually designed such that a seal is formed between an interior of the coupled casing joints and an annular space formed between exterior walls of the casing joints and walls of the wellbore. Further, the seal may be an elastomer seal (e.g., an o-ring seal) formed within a threaded connection to prevent liquid and/or gas from escaping out of the interior of the coupled casing joints. Accordingly, it may be desirable for a threaded connection to be able to effectively seal without relying, at least solely, on an elastomer seal, considering the high pressures and temperatures that are often encountered within the downhole environment.